Conventional practice of adjacent electric power companies is to interconnect to share generation and reserves, and thereby improve reliability and economy of service to users. The power industry has grown extensively during the past fifty years, and so have interconnections. As described in my chapter "Power Systems Interconnections--Control of Generation and Power Flow" in the 11th edition of the Standard Handbook for Electrical Engineers, McGraw Hill, N.Y., 1978, there are currently three large interconnected systems in the contiguous United States and portions of Canada.
The largest is the Eastern Interconnected System, extending from east of the Rocky Mountain to the eastern seaboard, and embracing parts of Eastern Canada. It includes some 220 utility companies or agencies of varying sizes, some investor-owned, some publicly-owned, arranged in about 100 control areas in six regions. Its present generating capacity is about 400 million kilowatts.
The second interconnected system extends from the Rocky Mountains to the Pacific Coast, embracing portions of Western Canada. It includes some 53 utility companies or agencies arranged in 33 control areas in four regions. Its present generating capacity is about 100 million kilowatts.
The third of the interconnected systems is in the state of Texas. It has seven control areas, and a generating capacity of about 30 million kilowatts.
There are many complexities to the reliable and economic operation of an interconnected electric power system composed of many independently owned companies or agencies, extending over thousands of square miles of territory, containing dozens or hundreds of electrical generating units of varying types and sizes, with hundreds of miles of telemetering channels, and serving millions of customers. Over the years, many concepts, technologies and processes for operating, monitoring and automatically controlling such a system have been well developed, and generally well embraced and applied by the industry. There are, however, some aspects of operation and control, particularly as they relate to system time deviation and unscheduled power transfers between areas, and their corrections, which have not until now been fully or satisfactorily resolved. Such matters, which have become of particular importance in light of the escalation of fuel prices and the growing need for energy conservation, are addressed in this invention, and solutions disclosed.
A control area of an interconnected system is that portion of the system, generally a company or agency or a group of companies or agencies operating as a pool, which is expected automatically to adjust its generation to follow its load changes, and to schedule and maintain bulk power transfers with other areas.
Two principal operating objectives of an interconnected system operating under a set frequency schedule and with preset schedules of bulk power transfers between areas are:
(1) to be certain that user power demand, wherever on the system it occurs, is met, and
(2) to allocate generation changes made in response to load changes to areas in which the load changes occurred.
Electric power systems are self-regulating. That is to say that self-regulating forces, which are the rotating masses of the system, the frequency coefficient of connected load, and the speed governors of turbine-generator units, act to maintain a balance between total system load and total system generation so long as generation capability is available somewhere on the system and load limits of equipment and lines are not reached. The nature of these self-regulating forces is discussed in my paper, "Power System Control Practices," Proceedings of the Ninth Annual Allerton Conference on Circuit and Systems Theory, Allerton Park, Ill. (1971). Load changes in any area are therefore accomodated initially by load and generation changes in all areas resulting in departures of system frequency and area net interchanges from their respective schedules.
Departures of system frequency integrate into system time deviation, hereinafter referred to as a "memory parameter" representing a summation of system frequency departures from schedule during a designated time period.
Departures of area net interchange from schedule integrate into area inadvertent interchange, also referred to hereinafter as a "memory parameter" representing a summation of area departures from net interchange schedule during a designated time period.
The self-regulating forces of an interconnected system thus fulfill the first principal operating objective of satisfying user demand wherever on the system it occurs. It does so, however, at the expense of system frequency, and by placing corresponding generation changes randomly among the areas of the system, depending on the frequency coefficient of area loads, and the number, sizes and speed-governor characteristics of the turbine-generator units in the various areas. To fulfill the second principal operating objective of allocating generation changes to areas where the changes in load demand occurred, a supplementary automatic control is required. Such a supplementary control is generally slower than the self-regulating forces, and in effect reallocates generation changes to the appropriate areas after the initial self-regulating accomodations of changes in demand.
It is accordingly conventional practice to equip each control area with supplementary control identified as "frequency-biased net interchange control" (sometimes referred to as net interchange bias control) for the regulation of bulk power transfers, i.e., power interchanges with other areas. Such controls have the following functions:
1. Adjust area generation to match changes in area load,
2. Maintain bulk power transfers on preset schedules as long as the system frequency is on its schedule,
3. Depart from preset transfer schedules as a function of frequency deviation when frequency departs from its schedule, thereby providing assistance to areas in need,
4. Participate in system frequency regulation,
5. Periodically correct for its own accumulated departures from interchange schedules, and
6. Correct periodically in concert with other areas for accumulated deviations in system time.
Frequency-biased net interchange control has been the standard operating technique in the United States, Canada and elsewhere in the world for more than thirty years. Its applicability and effectiveness for the first four of the six functions tabulated above, are well understood and documented, see my papers, "Power Flow Control--Basic Concepts for Interconnected Systems," Electric Light and Power, Chicago, Volume 28, Nos. 8 and 9 (1950), and "Some Aspects of Tie-Line Bias Control on Interconnected Power Systems," Transactions A.I.E.E., Vol. 75, Pt III (1957), and my book, "Control of Generation and Power Flow on Interconnected Systems," John Wiley & Sons, Second Edition (1971). On the other hand, present practices for items 5 and 6 related to corrections for accumulated departures from transfer schedules and time deviation are frequently inadequate and uneconomical, resulting in unnecessary regulation and corresponding waste of energy. I shall refer additionally later in this specification to these two items and to new concepts, methods and means for correction of present deficiencies.
In the application for a given area of frequency-biased net interchange control, measurements are made of system frequency and of the net of area power interchanges with other areas, settings are made of the system frequency schedule, the area net interchange schedule, and the area frequency bias setting, and from these parameters an area control error is determined. This in turn activates control apparatus which automatically adjusts the energy input to one or more turbine-generator units in the area so that area generation output is adjusted in magnitude and direction to reduce the area control error to zero. In this process: EQU E.sub.n =(T.sub.n -T.sub.on)-10 B.sub.n (F-F.sub.o) (1)
where
E.sub.n =the area control error of area n, in megawatts,
T.sub.n =the measured net interchange of the area with other areas, in megawatts, power out is +,
T.sub.on =the scheduled net interchange of the area, in megawatts, as preset, power out is +,
B.sub.n =the frequency bias setting for the area in MW/0.1 Hz, and is considered to have a minus sign,
F=system frequency in Hz,
F.sub.o =the system frequency schedule in Hz, as preset.
The control signals which are to effect the change in generation of the area generators are usually derived by coordination of the area control error signal with a number of other measured or computed parameters so that the effectiveness of the control and the economy and the security of the area are optimized while the area control error is being reduced to zero. Systems utilizing frequency biased net interchange control coordinated with other area objectives are disclosed in my U.S. Pat. No. 2,773,994, issued Dec. 11, 1956, my U.S. Pat. No. 2,831,125, issued Apr. 15, 1958, my U.S. Pat. No. 2,866,102, issued Dec. 23, 1958, my U.S. Pat. No. 3,076,898, issued Feb. 5, 1963, and my U.S. Pat. No. 3,270,209, issued Aug. 30, 1966.
For hypothetically perfect operation, the interconnection will automatically achieve its scheduled frequency, and net interchanges for all areas will be on their respective schedules when the area control error for each area is zero, and the following criteria are fulfilled:
1. All portions of the interconnection are included in one area or another so that the sum of all area generation, loads and losses is the same as the total system generation, load and losses.
2. The algebraic sum of all area net interchange schedules is equal to zero.
3. A common scheduled frequency is used for all areas, and
4. There are no metering or computational errors.
Such criteria and the requirement of returning the area control error for each area to zero are not always fulfilled. The reasons are:
1. There may be errors or offsets in one or more areas in setting the frequency schedule.
2. There may be errors or offsets in one or more areas in setting the net interchange schedules.
3. There may be errors in one or more areas in measuring system frequency.
4. There may be errors in one or more areas in measuring area net interchange.
5. There may be computational errors in one or more areas in calculating area control error, or
6. One or more areas may be unable or unwilling to adjust area generation in manner that will reduce the respective area control error to zero.
Each of these deficiencies will cause deviations of system frequency from schedule and deviations of net interchanges from schedules
Accumulations of frequency deviations from normal schedule become system time deviations, by: ##EQU1## where,
.epsilon.=system time deviation, in seconds,
F.sub.r =system reference frequency, in Hz,
F=system frequency, in Hz, and
t=time span in hours over which the time deviation has accumulated.
When system reference frequency is 60 Hz, Equation (2) becomes: EQU .epsilon.=60.sub.o.sup.t (F-60)dt (2a)
The term "regulating state" will be used to define the prevailing conditions within an area with respect to its control responsibilities. When an area is devoid of errors in setting its frequency and net interchange schedules, in measuring frequency and net interchange, and has zero area control error, which is to say it is without "regulating deficiencies," it will have a zero-error regulating state. The degree to which such regulating deficiencies exist within an area defines its regulating state, and results in a corresponding contribution by the area to system frequency deviation. Thus system time deviation may be regarded as related to the algebraic summation of the regulating states of all areas of the interconnected system during a designated time span.
Frequency-biased net interchange controls are cooperative controls, which not only act to reallocate the generation changes to the area where the load changes occurred, but cause other areas to provide generation assistance to the load change area until the latter responds to its own control system and makes the requisite generation changes. When, however, the area in which the load change occurred fails to properly adjust its generation, the system frequency deviation from schedule and the corresponding area net interchange deviations from respective schedules persist. System time deviation then continues to accumulate, as do inadvertent interchanges not only in the area responsible for the prevailing condition, but in all areas who are assisting it pending its own corrective action. While this condition of the load change area receiving assistance from the other areas persists, the load change area has a non-zero regulating state. Other areas are also accumulating inadvertent interchange, but if they are providing the preprogrammed assistance and have no other prevailing regulating deficiencies, they are in zero-error regulating states.
The portion of an area's total inadvertent interchange accumulation that is caused by the area's own non-zero regulating states is defined in this invention as "primary inadvertent." The portion of an area's total inadvertent interchange accumulation that is caused by the non-zero regulating states of other areas is defined as "secondary inadvertent."
System time deviation, being a summary of frequency deviations over a designated time span, may be regarded as a "system memory parameter."
Accumulations in area net interchange deviations from schedule are defined as "Inadvertent Interchange," which may be regarded as an "area memory parameter," and is given by: EQU I.sub.n =.sub.o.sup.t (T.sub.n -T.sub.on)dt (3)
where,
I.sub.n =inadvertent interchange of area n, in megawatt hours, energy out being +,
T.sub.n =net interchange of the area, in megawatts, power out being +,
T.sub.on =net interchange schedule of the area, in megawatts, and
t=time span in hours over which the inadvertent interchange has accumulated.
Significant or frequent accumulations of system time deviation or area inadvertent interchange are deemed by system operators as undesirable. Unscheduled assistance to areas having regulating deficiencies is costly to the assisting areas. Also, such accumulations create the need for costly corrective control action to counterbalance past accumulations so that system time deviation is reduced to acceptable limits for system synchronous clocks, and area inadvertent interchanges are reduced to zero. A reason for the latter requirement, is that current practice is for each area to transfer energy to or to receive energy from other areas to compensate for past accumulations of unscheduled interchanges between one another. The compensating transfers may be made when a unit of energy, because of the time of day and the prevailing loading of the area, may have a value substantially different than the value existent when the unscheduled transfer was made.
Further, unscheduled transfers may reduce or fully absorb the available capacity margins of interconnecting transmission lines, so that power transfers to areas in need during emergencies may not be possible.
Despite the general agreement by system operators that good regulation by each control area is a desirable objective, and assistance from other areas should be provided primarily during emergency periods, there has nevertheless been a "deterioration" in area control performance in recent years. This is reported in the 1975 Annual Report of the National Electric Reliability Council, Princeton, N.J., by the North American Power Systems Interconnection Committee (NAPSIC), a voluntary coordinating organization representing most of the interconnected utilities in the United States and portions of Canada. To monitor, to take steps to correct for such regulating deficiencies, and to provide control that will help avoid them, requires that means be available to determine which area or areas are at fault, and by how much. In other words, how much of the accumulated system time deviation was caused by the non-zero regulating states of which areas, and how much of an area's inadvertent interchange is due to its own ineffective operation and how much is the result of assistance cooperatively given to areas in need?
Failure of an area to regulate effectively is costly to other areas. A precise performance measure would make it possible to identify the area or areas at fault, to encourage them to improve control performance as justification for their participation in the interconnected system, and would provide a means for effective control by each area for its past faults and errors.
Many of the points raised or questions asked by authors Connor, Denny, Huff, Kennedy and Frank concerning area and system regulation in the paper, "Current Operating Problems Associated With Automatic Generation Control," Paper No. 77 810-5 presented at the IEEE/ASME/ASCE Joint Power Generation Conference, Los Angeles, CA, September 18-21, 1977, could be answered given the availability of a precise measure of area control performance. Although techniques for such measurements have been developed and some are still in use, a truly precise practical means for measuring area control performance has not been available in the more than thirty years that frequency-biased net interchange control for all areas of an interconnected system has been in use.
Two techniques are currently in use for checking area control performance. One involves an analysis of area control error, and is described in the "Control Performance Criteria" supplement to the NAPSIC "Operating Manual" dated 1973, revised 1977. This has distinct limitations, however, for as noted in the criteria itself, "it does not take into account errors in measurement, telemetering, schedules, etc." A second technique used by NAPSIC systems is a "Control Error Survey." Here computations are made for all areas over a designated time period of the difference between an area's total inadvertent interchange accumulation and the product of the area's bias setting times one-sixth the system time deviation. As will be shown later in this specification, this computation produces inaccurate results and hence an inaccurate comparison of the regulating effectiveness of each of the areas. Both of the NAPSIC techniques are described by contributing author Huff in the paper, "Current Operating Problems Associated with Automatic Generation Control" already referred to.
It will now be useful to examine and cite the limitations of the prevailing industry techniques for corrective control of accumulations in system time error and in area inadvertent interchanges prior to disclosing the improvements for such control provided by this invention.
As described in Operating Guide No. 4 of the NAPSIC Operating Manual, already referred to, system time deviation correction is achieved by all control areas offsetting frequency schedule in the direction that will adjust generation to speed up or slow down system frequency to counterbalance the accumulated time deviation. As noted in the Guide, all control areas are expected to participate in time deviation correction, on instructions from the central timekeeping area, American Electric Power Company at Canton, Ohio, and the frequency schedule offset at present is minus or plus 0.02 Hz when a plus or minus two second error has developed. In effect, a non-zero regulating state is established by all control areas to compensate for the previous non-zero regulating states in the opposite direction that caused the system time deviation.
This procedure, with minor variations, has been standard on U.S. and Canadian interconnections for more than thirty years. While it corrects system time, it has the disadvantage that all areas are expected to participate in the time correction action, with its accompanying regulation of generation, although not all areas have shared in creating the prevailing time deviation. I shall show that such participation by all areas is, for some of them, counterproductive not only because of the costly regulation it requires, but also because this very action creates elements of inadvertent interchange for those areas which did not share in creating the prevailing system time deviation, and their contribution to its correction amounts to the creation, for them, of a new error for which they must later regulate additionally, in the opposite direction, to correct, and in the process will be recreating a component of the original system time deviation.
Operating Guide No. 5 of the previously referred to Operating Manual of NAPSIC describes presently approved techniques for area inadvertent interchange corrective control. Two methods are recommended. The first is a bilateral approach, wherein one area with inadvertent interchange in one direction arranges with another area having inadvertent interchange to the opposite direction to offset their respective net interchange schedules by the same amount but in the opposite directions, thereby correcting the inadvertent interchange of both areas, without creating a change in system-frequency or time deviation. On the face of it, this appears like an appropriate procedure. I shall show, however, that in many cases it is not, because the total inadvertent interchange of an area may well be wholly or in part secondary inadvertent, due to regulating deficiencies of other areas, which only such other areas can correct. When an area endeavors to correct for the secondary component of inadvertent interchange caused by the primary component of inadvertent interchange of other areas, it cannot, as I shall show, do so, but instead is creating primary inadvertent interchange of its own for which it must later itself correct.
The second technique for inadvertent interchange corrective control approved by NAPSIC in Operating Guide No. 5 of the previously referred to Operating Manual, is for a single area, unilaterally, to correct for its total inadvertent interchange if it is in the direction that aids in the correction of existing time error. This also has limitations, since such corrective control for its own total inadvertent interchange by an area (1) may not actually be correcting for that portion of its total inadvertent interchange for which it itself is responsible, namely, its primary component which may well be of opposite algebraic sign to its total inadvertent interchange, and (2) to the extent that it is correcting for secondary components of its inadvertent interchange for which other areas are responsible, it will only be creating primary inadvertent interchange for itself and secondary components for others, all of which must later be correctively controlled. Also, correlation between inadvertent interchange of an area and prevailing system time error is not necessarily a correct correlation. As I will show, the correlation should be between that portion of total inadvertent interchange for which the area itself is responsible, its primary component, and that portion of system time deviation for which that area is itself responsible.
Thus the NAPSIC Operating Guides for system-wide time error corrective control and unilateral or bilateral inadvertent interchange corrective control, Nos. 4 and 5 respectively, may well result in improper control action which does not control for the parameters that the area needs to regulate, and will result in the need for further additional regulation later to undo that which the control action has improperly done. Generating units operate more efficiently where base loaded with fixed output, than when inputs are altered to obtain the varying output needed when regulating. Regulation consumes energy. The improved control techniques of this invention, which will reduce unnecessary or counterproductive regulation, will thereby result in energy conservation.
In a paper, "Techniques for Improving the Control of Bulk Power Transfers on Interconnected Systems," presented at the 1971 IEEE Winter Power Meeting and published in IEEE Transactions, Volume PAS-90, No. 6 (1971), hereinafter referred to as the "1971 paper" I made an analysis of the effects on frequency, net interchange, inadvertent interchange and system time deviation of various types of errors or control inadequacies in a given area. The same material, with slightly different symbology, discussed from the viewpoint of system operators, was presented under the title, "Energy Balancing on Interconnected Systems," at the 1973 American Power Conference and published in the Proceedings of that Conference, Volume 35, Chicago, IL, 1973.
The frequency-biased net interchange control equation,, Equation (1), was expanded in these publications to include area measuring and schedule setting errors and offsets as follows: EQU E.sub.n =(T.sub.n +.tau..sub.1n -T.sub.on -.tau..sub.on)-10B.sub.n (F+.phi..sub.1n -F.sub.o -.phi..sub.on) (4)
where,
.tau..sub.1n =errors in measurement of T.sub.n,
.tau..sub.on =errors or offsets in setting T.sub.on,
.phi..sub.1n =errors in measurement of F,
.phi..sub.on =errors or offsets in setting F.sub.o.
The following relationships were also outlined in the referenced papers: EQU .tau..sub.n =.tau..sub.on -.tau.1n (4a)
where
.tau..sub.n =the algebraic sum of errors in T.sub.n, and errors or offsets in T.sub.on. EQU .phi..sub.n =.phi..sub.on -.phi..sub.1n ( 4b)
where,
.phi..sub.n =the algebraic sum of errors in F, and errors or offsets in F.sub.o. EQU T'.sub.n =T.sub.n +.tau..sub.1n ( 4c)
where,
T'.sub.n is the area n net interchange as measured. EQU T'.sub.on =T.sub.on +.tau..sub.on ( 4d)
where,
T'.sub.on is the area n net interchange schedule as set. EQU F.sub.n '=F+.phi..sub.ln ( 4e)
where,
F'.sub.n is the area n frequency as measured. EQU F.sub.on '=F.sub.o +.phi..sub.on ( 4f)
where,
F'.sub.on is the area n frequency schedule as set.
From which: EQU E.sub.n =(T.sub.n '-T.sub.on ')=10B.sub.n (F.sub.n '-F.sub.on ') (4g)
From Equations (1), (4a) and (4b): EQU E.sub.n =(T.sub.n -T.sub.on -.tau..sub.n)-10B.sub.n (F-F.sub.o -.phi..sub.n) (4h)
Reference will be made to these relationships as the disclosure proceeds.
In the same references, the equations developed for system time deviation and total area inadvertent interchange are indicative of the fact that each of these parameters is made up of components, each specifically related to a specific area. The equations are, however, in terms of unknown or non-measurable parameters such as .tau..sub.n and .phi..sub.n, and though of theoretical interest, have not been of practical value.
As concerns the components of area inadvertent interchange, these have traditionally been identified as the "intentional" and "unscheduled" components, in "Definitions of Terminology for Automatic Generation Control on Electric Power Systems," IEEE Publication No. 94 (1965). The latter term is frequently referred to in power systems practice, as the "unintentional" components, as noted in my paper, "Considerations in the Regulation of Interconnected Areas," IEEE Transactions, Volume PAS-86, No 12 (1967).
The "intentional" inadvertent was intended to define the area schedule deviation that occurs when making an assisting frequency-biased contribution to other areas, because of unfulfilled needs existing there. An equation for this component appears in my aforementioned paper, "Considerations in the Regulation of Interconnected Areas," but as noted therein, applies only to the special case of an area having zero control error. There is, however, ambiguity in the current use of the terms "intentional" and "unintentional." For example, consider that an area offsets its net interchange or frequency schedule to correctively control for inadvertant interchange or time deviation. That constitutes an intentional offset, but since it is not a result of frequency bias action, the resultant inadvertent is not regarded as "intentional." Similarly, if an area consciously decides that it does not want to regulate effectively, that is an intentional decision but it results in "unintentional" or unscheduled inadvertent.
For this disclosure I will utilize the new terminology referred to earlier, namely, "primary inadvertent" for that component of total area inadvertent interchange that results from its own inadequacies, errors or schedule offsets which is to say, its own regulating deficiencies, while "secondary inadvertent" will refer to that component of an area's total inadvertent interchange that reflects responses to regulating deficiencies in remote areas.
Other techniques for correcting area inadvertent interchange and system time deviation accumulations, though not now in use, have been disclosed in my U.S. Pat. Nos. 3,701,891 (1972) and 3,898,442 (1975).
The first, recognizing that the algebraic sum of inadvertent interchange for all control areas of the interconnected system is zero, but pursuing the traditional concept that time correction and inadvertent interchange correction are separate objectives, suggested that inadvertent interchange correction take place at stipulated times with participation by all areas, and at the same time that system-wide correction of time deviation by all areas was taking place. Two characteristics of this proposed technique as disclosed in U.S. Pat. No. 3,701,891, are that all areas are to participate in the inadvertent interchange correction and the inadvertent interchange correction would not necessarily be completed in the same time span as would the time deviation correction. The technique of the second of the two U.S. Pat. No. 3,898,442, described also in my paper, "Some New Thoughts on Energy Balancing and Time Correction on Interconnected Systems," published in the Proceedings of the IEEE Region Five Conference on "Control of Power Systems," IEEE Publication T6CH1057-9REG5 (1976), while still considering two separate control objectives, and still specifying that all areas participate simultaneously in inadvertent interchange correction, defines relationships between the modifiers for the inadvertent interchange correction factors and the time deviation correction factors which insure that both sets of corrections would be completed in the same time span.